Pump protection components have been proven to protect pumps from sand and extend the operational life of ESPs in unconventional wells.This solution controls the backflow of frac sand and other solids that can cause overloads and downtime.The enabling technology eliminates the problems associated with particle size distribution uncertainty.
As more and more oil wells rely on ESPs, extending the life of electrical submersible pumping (ESP) systems becomes increasingly important.The operating life and performance of artificial lift pumps are sensitive to solids in produced fluids.The operating life and performance of the ESP decreased significantly with the increase in solid particles.In addition, solids increase the well downtime and workover frequency required to replace the ESP.
Solid particles that often flow through artificial lift pumps include formation sand, hydraulic fracturing proppants, cement, and eroded or corroded metal particles.Downhole technologies designed to separate solids range from low-efficiency cyclones to high-efficiency 3D stainless steel wire mesh.Downhole vortex desanders have been used in conventional wells for decades, and they are primarily used to protect pumps from large particles during production.However, unconventional wells are subject to intermittent slug flow, which results in existing downhole vortex separator technology only working intermittently.
Several different variants of combined sand control screens and downhole vortex desanders have been proposed to protect ESPs.However, there are gaps in the protection and production performance of all pumps due to the uncertainty in the size distribution and volume of solids produced by each well.Uncertainty increases the length of sand control components, thereby reducing the depth at which the ESP can be set, limiting the ESP’s reservoir decline potential, and negatively impacting well economics.Deeper setting depths are preferred in unconventional wells.However, the use of de-sanders and male-plug mud anchors to suspend long, rigid sand control assemblies in casing sections with high dogleg severity limited ESP MTBF improvements.Corrosion of the inner tube is another aspect of this design that has not been adequately evaluated.
The authors of a 2005 paper presented experimental results of a downhole sand separator based on a cyclone tube (Figure 1), which depended on cyclone action and gravity, to show that separation efficiency depends on oil viscosity, flow rate, and particle size .They show that the efficiency of the separator is largely dependent on the terminal velocity of the particles.Separation efficiency decreases with decreasing flow rate, decreasing solid particle size, and increasing oil viscosity, Figure 2.For a typical cyclone tube downhole separator, the separation efficiency drops to ~10% as the particle size drops to ~100 µm. In addition, as the flow rate increases, the vortex separator is subject to erosion wear, which affects the use of structural components life.
The next logical alternative is to use a 2D sand control screen with a defined slot width.Particle size and distribution are important considerations when selecting screens to filter solids in conventional or unconventional well production, but they may be unknown.The solids may come from the reservoir, but they may vary from heel to heel; alternatively, the screen may need to filter sand from hydraulic fracturing.In either case, the cost of solids collection, analysis and testing can be prohibitive.
If the 2D tubing screen is not properly configured, the results can compromise the economics of the well.Sand screen openings that are too small can result in premature plugging, shutdowns and the need for remedial workovers.If they are too large, they allow solids to freely enter the production process, which can corrode oil pipes, damage artificial lift pumps, flush out surface chokes and fill surface separators, requiring sandblasting and disposal.This situation requires a simple, cost-effective solution that can extend the life of the pump and cover a wide distribution of sand sizes.
To meet this need, a study was conducted on the use of valve assemblies in combination with stainless steel wire mesh, which is insensitive to the resulting solids distribution.Studies have shown that stainless steel wire mesh with variable pore size and 3D structure can effectively control solids of various sizes without knowing the particle size distribution of the resulting solids.The 3D stainless steel wire mesh can effectively control the sand grains of all sizes, without the need for extra secondary filtration.
A valve assembly mounted on the bottom of the screen allows production to continue until the ESP is pulled out.It prevents ESP from being retrieved immediately after the screen is bridged.The resulting inlet sand control screen and valve assembly protects ESPs, rod lift pumps, and gas lift completions from solids during production by cleaning fluid flow and provides a cost-effective solution to extend Pump life without having to tailor reservoir characteristics for different situations.
First generation pump protection design.A pump protection assembly using stainless steel wool screens was deployed in a steam assisted gravity drainage well in Western Canada to protect the ESP from solids during production.Screens filter harmful solids from the production fluid as it enters the production string.Within the production string, fluids flow to the ESP inlet, where they are pumped to the surface.Packers can be run between the screen and the ESP to provide zonal isolation between the production zone and the upper wellbore.
Over production time, the annular space between the screen and casing tends to bridge with sand, which increases flow resistance.Eventually, the annulus bridges completely, stops flow, and creates a pressure differential between the wellbore and the production string, as shown in Figure 3.At this point, fluid can no longer flow to the ESP and the completion string must be pulled. Depending on a number of variables related to solids production, the duration required to stop flow through the solids bridge on the screen may be less than the duration that would allow the ESP to pump the solids laden fluid mean time between failures to the ground, so the second generation of components was developed.
The second generation pump protection assembly.The PumpGuard* inlet sand control screen and valve assembly system is suspended below the REDA* pump in Figure 4, an example of an unconventional ESP completion.Once the well is producing, the screen filters the solids in production, but will begin to slowly bridge with the sand and create a pressure differential.When this differential pressure reaches the valve’s set cracking pressure, the valve opens, allowing fluid to flow directly into the tubing string to the ESP.This flow equalizes the pressure differential across the screen, loosening the grip of the sandbags on the outside of the screen.Sand is free to break out of the annulus, which reduces flow resistance through the screen and allows flow to resume.As the differential pressure drops, the valve returns to its closed position and normal flow conditions resume.Repeat this cycle until it is necessary to pull the ESP out of the hole for servicing.The case studies highlighted in this article demonstrate that the system is able to significantly extend the life of the pump compared to running screening completion alone.
For the recent installation, a cost-driven solution was introduced for area isolation between the stainless steel wire mesh and the ESP.A downward facing cup packer is mounted above the screen section.Above the cup packer, additional center tube perforations provide a flow path for produced fluid to migrate from the interior of the screen to the annular space above the packer, where the fluid can enter the ESP inlet.
The stainless steel wire mesh filter chosen for this solution offers several advantages over gap-based 2D mesh types.2D filters rely primarily on particles spanning filter gaps or slots to build sandbags and provide sand control.However, since only a single gap value can be selected for the screen, the screen becomes highly sensitive to the particle size distribution of the produced fluid.
In contrast, the thick mesh bed of stainless steel wire mesh filters provides high porosity (92%) and large open flow area (40%) for the produced wellbore fluid.The filter is constructed by compressing a stainless steel fleece mesh and wrapping it directly around a perforated center tube, then encapsulates it within a perforated protective cover that is welded to the center tube at each end.The distribution of pores in the mesh bed, the non-uniform angular orientation (ranging from 15 µm to 600 µm) allows harmless fines to flow along a 3D flow path towards the central tube after larger and harmful particles are trapped within the mesh.Sand retention testing on specimens of this sieve demonstrated that the filter maintains high permeability because fluid is generated through the sieve.Effectively, this single “size” filter can handle all particle size distributions of produced fluids encountered.This stainless steel wool screen was developed by a major operator in the 1980s specifically for self-contained screen completions in steam stimulated reservoirs and has an extensive track record of successful installations.
The valve assembly consists of a spring-loaded valve that allows one-way flow into the tubing string from the production area.By adjusting the coil spring preload prior to installation, the valve can be customized to achieve the desired cracking pressure for the application.Typically, a valve is run under the stainless steel wire mesh to provide a secondary flow path between the reservoir and the ESP.In some cases, multiple valves and stainless steel meshes operate in series, with the middle valve having a lower cracking pressure than the lowest valve.
Over time, formation particles fill the annular area between the outer surface of the pump protector assembly screen and the wall of the production casing.As the cavity fills with sand and the particles consolidate, the pressure drop across the sandbag increases.When this pressure drop reaches a preset value, the cone valve opens and allows flow directly through the pump inlet.At this stage, the flow through the pipe is able to break up the previously consolidated sand along the exterior of the screen filter.Due to the reduced pressure differential, flow will resume through the screen and the intake valve will close.Therefore, the pump can only see the flow directly from the valve for a short period of time.This prolongs the life of the pump, as most of the flow is the fluid filtered through the sand screen.
The pump protection system was operated with packers in three different wells in the Delaware Basin in the United States.The main goal is to reduce the number of ESP starts and stops due to sand-related overloads and to increase ESP availability to improve production.The pump protection system is suspended from the lower end of the ESP string.The results of the oil well show stable pump performance, reduced vibration and current intensity, and pump protection technology.After installing the new system, sand and solids related downtime was reduced by 75% and pump life increased by more than 22%.
A well.An ESP system was installed in a new drilling and fracturing well in Martin County, Texas.The vertical portion of the well is approximately 9,000 feet and the horizontal portion extends to 12,000 feet, measured depth (MD).For the first two completions, a downhole vortex sand separator system with six liner connections was installed as an integral part of the ESP completion.For two consecutive installations using the same type of sand separator, unstable behavior of the ESP operating parameters (current intensity and vibration) was observed.Disassembly analysis of the pulled ESP unit revealed that the vortex gas separator assembly was clogged with foreign matter, which was determined to be sand because it is non-magnetic and does not chemically react with acid.
In the third ESP installation, stainless steel wire mesh replaced the sand separator as a means of ESP sand control.After installing the new pump protection system, the ESP exhibited more stable behavior, reducing the range of motor current fluctuations from ~19 A for installation #2 to ~6.3 A for installation #3.Vibration is more stable and the trend is reduced by 75%.The pressure drop was also stable, fluctuating very little compared to the previous installation and gained an additional 100 psi of pressure drop.ESP overload shutdowns are reduced by 100% and ESP operates with low vibration.
Well B. In one well near Eunice, New Mexico, another unconventional well had an ESP installed but no pump protection.After the initial boot drop, the ESP started to exhibit erratic behavior.Fluctuations in current and pressure are associated with vibration spikes.After maintaining these conditions for 137 days, the ESP failed and a replacement was installed.The second installation includes a new pump protection system with the same ESP configuration.After the well resumed production, the ESP was operating normally, with stable amperage and less vibration.At the time of publication, the second run of ESP had reached over 300 days of operation, a significant improvement over the previous installation.
Well C.The system’s third on-site installation was in Mentone, Texas, by an oil and gas specialty company that experienced outages and ESP failures due to sand production and wanted to improve pump uptime.Operators typically run downhole sand separators with liner in each ESP well.However, once the liner fills with sand, the separator will allow the sand to flow through the pump section, corroding the pump stage, bearings and shaft, resulting in a loss of lift.After running the new system with the pump protector, the ESP has a 22% longer operating life with a more stable pressure drop and better ESP-related uptime.
The number of sand and solids-related shutdowns during operation decreased by 75%, from 8 overload events in the first installation to two in the second installation, and the number of successful restarts after overload shutdown increased by 30%, from 8 in the first installation. A total of 12 events, for a total of 8 events, were performed in the secondary installation, reducing electrical stress on the equipment and increasing the operational life of the ESP.
Figure 5 shows the sudden increase in the intake pressure signature (blue) when the stainless steel mesh is blocked and the valve assembly is opened.This pressure signature can further improve production efficiency by predicting sand-related ESP failures, so replacement operations with workover rigs can be planned.
1 Martins, JA, ES Rosa, S. Robson, “Experimental analysis of swirl tube as downhole desander device,” SPE Paper 94673-MS, presented at the SPE Latin America and Caribbean Petroleum Engineering Conference, Rio de Janeiro, Brazil, June 20 – February 23, 2005.https://doi.org/10.2118/94673-MS.
This article contains elements from SPE paper 207926-MS, presented at the Abu Dhabi International Petroleum Exhibition and Conference in Abu Dhabi, UAE, 15-18 November 2021.
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